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MV Overhead FeederAutomation Sophistication
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Introduction
Due to the importance of electricity in the everyday life of
people, electricity providers are under immense pressure to improve
the reliability of supply to their customers. Providers have a
number of options available to improve supply reliability.
Additional primary substationsTo a large degree the likelihood
of fault is proportional to the length of distribution circuit, and
obviously the longer the circuit the greater the probability of a
fault.It is possible to reduce the feeding distances substantially
by installing additional primary substations. That is also going to
reduce the number of customers affected by each fault. Installing
new substations can however be very expensive.
Additional feeder circuitsNew feeders could be established from
existing primary substations and this option also reduces the
number of customers per circuit and therefore the number of
customers affected by each fault. This option would however be less
effective than the addition of primary substations and may not be
very efficient. It is again negated by excessive cost.
Vegetation managementBoth of the first two options focus on
reducing the affects of faults but do not in themselves do anything
to reduce the number of faults. One thing that all utilities, with
overhead rural feeders, have to focus upon is vegetation
management. This is of course an operational expenditure rather
than a capital expenditure but nevertheless an extremely important
activity for electrical utilities and essential if unnecessary
interruptions are to be avoided.
Covered ConductorAnother option to reduce the number of faults
would be to remove bare overhead conductors and replace them with
covered conductors. This will reduce faults caused by birds,
animals, tree branches or other wind blown material contacting the
line. Using covered conductor particularly in wooded areas will
help to reduce faults. Covered conductors are certainly not fool
proof and its performance under high impulse conditions can be a
problem. The biggest drawback with it however is the cost.
Replacing the conductors in large portions of the network is not
generally an economically viable option.
Underground circuitsA theoretically better option again would be
to underground all circuits. This would remove any weather or
vermin related faults and will undoubtedly improve reliability and
win favour with environmentalist lobby groups. The use of
trench-less or narrow trench technology can significantly reduce
cost. However considering the feeding distances involved the cost
would still be astronomical. A significant redesign of networks
would also be required, as the typical overhead circuit with very
long feeding distancs and many spur lines teed-off is not really
suited to an underground system.Some practical difficulties could
be manifested in complications with future fault location which
could cause long interruptions to supply. Low cost, pad mounted
transformers and switchgear would be an essential requirement of
such a system.
Feeder automation sophisticationIn an effort to improve
reliability of supply, providers are rethinking the levels of
sophistication deployed in their Medium Voltage (MV) Overhead
Feeders.Studies of faults on overhead feeder networks have shown
that 60 - 70% of the faults are transient/temporary.Examples of
transient faults include:b Conductors clashing in the wind;
b Tree branches falling on overhead conductors;
b Animals or birds coming in contact with overhead conductors;
and
b Lightning strikes.
An auto-reclose cycle should clear a transient fault without
interrupting supply to the customer. In most cases no further
operator assistance would be required to clear the fault.Some
faults are however more permanent. Examples include
distribution
Figure 1: Permanent Fault Example
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equipment, such as transformer, failures and fallen power lines
due to motor accidents or storms. Protection equipment is designed
to minimise damage by interrupting supply to a segment containing a
fault. The supply will remain off until the fault is removed and
the protection equipment is turned back on.During a permanent fault
the following actions would typically be taken to minimise the
effects of the fault:b Protection equipment (circuit breaker or
recloser) would interrupt supply to the affected segment/s of the
feeder.
b Identify the faulty segment of the feeder.
b For looped networks isolate the faulty segment by opening the
switchgear upstream and downstream of the fault.
b Reconfigure the network for alternative power flow.
b Restore power upstream of the faulty segment.
b If an open loop network is used, close the open point to
restore power downstream of the faulty segment.
b Maintenance crews remove the fault.
b Restore the network to the normal configuration.
It is possible that outages can last for hours and even days. To
minimise the duration of the outages it is necessary to quickly
identify the exact location of the fault and to provide alternative
power supplies to segments not containing the fault. This can be
done manually or by using sophisticated switchgear controllers to
enable electricity providers to incorporate advanced automation
functions in Feeder Networks thus substantially reducing the outage
time.This paper explores the effectiveness of feeder segmentation
and considers the effects of using different arrangements or types
of switchgear to construct an overhead MV network run as an open
ring.Two possible scenarios giving increasing levels of automation
sophistication are compared for cost and benefits, and operational
risks under fault conditions:b Telecontrolled switches in a
remotely controlled, but not necessarily automated network; and
b Reclosers and sectionalisers in an automated, but not
necessarily remotely-controlled network.
A glossary is provided at the end of the document.
Figure 2: Open Loop Network Example
Introduction
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As discussed in the Introduction of this paper, supply
authorities have a number of options available to improve the
reliability of supply. These are:b Additional primary substations;b
Additional feeder circuits;b Vegetation management;b Covered
Conductor;b Underground circuits; andb Feeder automation
sophistication.Reliability gains are also made by increasing the
protection sophistication. This is not limited to the latest
protection algorithms. It also includes breaking the feeder into
smaller segments. This reduces the number of customers per segment
and therefore the number of customers affected by a fault. The
following paragraph explores the affect that segment lengths have
on reliability.
Increased number of segments per feederFor this example,
consider a theoretical radial feeder. Assume that the probability
of a fault is the same along the length of the feeder. By dividing
the feeder into multiple segments the probability that a fault
would occur in a specific segment is:PZ = PF x (LZ / L) where:L =
the length of the feeder;LZ = the length of the segment; andPF =
the probability that a fault would occur anywhere on the feeder.It
is possible to calculate the impact when the feeder is divided into
multiple segments of equal length.
Unfortunately these improvement figures do not tell the full
story. To get the full picture it is necessary to revisit the basic
radial feeder, look at the probability of an outage in each segment
and then expand the theory to a looped network.
Number of Segments
Segment fault probability
Improvement
1 P1 = PF
2 P2 = PF x 50% P2 / P1 = 50%
3 P3 = PF x 33% P3 / P2 = 66%
4 P4 = PF x 25% P4 / P3 = 75%
Table 1:Reliability Improvement
Radial feeder
The example above clearly shows how the outages in each segment
are affected by the number of faults in that specific segment and
the faults occurring in upstream segments.Looped networks are used
to reduce the number of outages for segments located further away
from the substation and to overcome this stepped increase in
outages.
Seg A B C D
Where "F" represents the switchgear closest to the substation
and "MP" represent switchgear anywhere along the feeder.
Probability of a fault in each segment is:
PA PB PC PD
Probability of an outage in each segment is:
PS PS+A PS+A+B PS+A+B+C PS+A+B+C+D
Where PS is the probability of losing supply at the primary
substation. PS should be negligible and this simplifies the
probability of an outage in each segment. (Notation: PA+B+C+D = PA
+ PB +PC + PD).
PA PA+B PA+B+C PA+B+C+D
For equal segment lengths and by using PZ = PF x (LZ / L) and
the above it is possible to show what percentage of permanent
faults will affect each segment. For feeders with four
segments:
4 25% 50% 75% 100%
For feeders with three segments:
3 33% 66% 100%
For feeders with two segments:
2 50% 100%
Notice how the probability of an outage increases further away
from the substation. From this example it is clear that not all
customers benefit equally from additional segments on the feeder.
Only customers connected to the first segment will experience the
improvements calculated in Table 1.
Table 2: Radial Feeder
F MP1 MP2
Feeder segmentation
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Open loop networkIn a looped network, the switchgear immediately
upstream and downstream of a fault are opened to isolate the fault,
and the normally-open point is closed to restore power downstream
of the faulty segment. Only the segment containing the fault
experiences an outage until the fault is removed and the network is
restored to the original configuration.The outage probability of
each segment is therefore not affected by the probability in
adjacent segments.
By reducing the length and increasing the number of segments in
a feeder it is possible to improve the reliability of supply.
However not all customers benefit equally from this investment and
looped networks are often used to improve supply reliability
throughout the feeder. Feeder segmentation is achieved by using
different technologies ranging from sophisticated reclosers and
sectionalisers through telecontrolled load-break switches to
manually operated air-break switches. The technology used in
feeders differs from country to country and is also affected by the
population density (number of customers per segment). In reality
underground circuits may be used in the inner city, reclosers in
substations and outer city feeders and sectionalisers in rural
feeders.The subsequent sections discuss in detail the benefit and
operation of each technology based on a common feeder topology.
How would a looped network affect these figures?
Seg A B C D
Probability of an outage in a looped network is:
PA PB PC PD
For feeders with multiple segments of equal length the
probability of an outage in each segment is 25%, 33% or 50%
respectively for four, three or two segments.By comparing these
probability figures to those determined for a radial feeder it is
possible to calculate the improvements achieved with a loop
network.
4 25% 25% 25% 25%
Improvement 25% 50% 75%
3 33% 33% 33%
Improvement 33% 66%
2 50% 100%
Improvement 50%
Table 3: Open Loop Network
F MP1 MP2 NO
Feeder segmentation
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In this example, remotely-controlled load-break switches
(commonly referred to as telecontrolled switches) are used in an
overhead feeder. Remotely-monitored Fault Passage Indicators (FPIs)
are used with the load-break switches, sometimes separately,
sometimes built into the switch. The switches are used for general
switching operations and in the event of a permanent fault, an
operator uses the FPI indication to determine which switches to
open in order to isolate the faulted segment of the feeder. To
operate such a network, a communications system is necessary, and
the operation of the switches is typically performed manually in a
control room. During a fault condition the feeder reconfiguration
is typically not automatic.
NO
Substation circuit breaker/recloserClosed telecontrolled
switchOpen telecontrolled switch
Figure 3: Typical Switch Network
Basic operation during fault conditionsWhen a permanent fault
occurs, the following steps are taken:b The substation circuit
breaker or recloser trips automatically to interrupt supply to the
affected feeder;
b An operator in the control room:v identifies the faulty
segment of the feeder by using the FPI indication displayed in the
control room;v opens (via a communications network such as optical
fibre) the nearest upstream and downstream switches to isolate the
faulty segment;v reconfigures the protection in substation
breakers;v closes the substation circuit breaker to restore power
upstream of the faulty segment, andv closes the normally-open point
to restore power downstream of the faulty segment.Power is restored
to the healthy parts of the network and it is possible for the
operator to despatch the maintenance crews to the faulted segment
of the feeder to remove the fault. Once the entire feeder is
healthy, the operator can open the normally-open point and close
the telecontrolled switches to restore the network to the normal
configuration.
Operational risksControl roomThe reaction time of the control
room has a significant impact on the feeder restoration times. In
practice the reaction time is influenced by:b The availability of
an operator 24 hours per day, 7 days a week;
b Enough operators to monitor and react during periods of
extreme fault activity, such as large storms;
b Reliability of communications to monitor FPI indication and to
control the switchgear;
b Feeder complexity; and
b Level of automation in control room and network.
However, if managed correctly, control room operations may not
degrade the operational efficiency of this type of network.
Fault passage indicationFPIs are the "eyes" of the operator.
When the operator does not have a clear understanding of the fault
location the operational efficiency of the network will be
reduced.FPI functionality can be incorporated in the switchgear.
These utilise switchgear mounted Current Transformers (CTs) and
sensing electronics to detect fault conditions. FPIs can also be
separate from the switchgear and these typically measure the
magnetic field around the transmission line and are simply clipped
onto the conductor making it extremely easy to install. The major
advantage of clip-on FPIs is that they can be installed anywhere
along the feeder, at different intervals and it is possible to
relocate them as requirements change.Two risks are associated with
FPIs - false indication and no indication at all.
Figure 4: Telecontrolled Load-Break Switch
Telecontrolled switches
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False indication is the situation where the FPI indicates a
fault without a fault being present. This can be caused by inrush
currents during switching operations and reclosing cycles. In
general, no indication can occur when low level phase and earth
fault conditions are not detected by the FPIs, resulting in the
absence of FPI indication. It is possible to overcome these risks
by matching the detection capabilities of the FPI to that of the
primary protection devices in the feeder.It is also possible that
the absence of indication is caused by communication failure.In
either case, an operator, may be left with a dead feeder and
misleading FPI indication on the mimic panel. This will mislead the
operator as to the actual location of the faulted segment,
resulting in incorrect switching operations and increased time
taken to restore power.
CommunicationsThe integrity of the telecontrolled switch network
relies wholly on the availability of communications and this key
part of the system affects all aspects of network operation. During
a fault condition the protection equipment will trip and without
communications the operator will not be able to reconfigure and
restore supply. Maintenance crews will have to locate the fault and
manually reconfigure the network by driving to each unit before
power is restored. This will take many hours and will cause
unacceptable delays in restoring power to the customers.
Advantages b Relatively low initial cost of switchgear.
b Much lower outage times when compared with manually-operated
switches without communications.
Disadvantages b Faults affect all customers connected to the
feeder.
b As the switches are manually, remotely operated, the duration
of the outage is dependent on the response time of the
operator;
b Expensive communications infrastructure;
b Operation is highly dependent on the integrity of the
communications network;
b All faults cause substation circuit breaker operation - this
results in a shorter service life.
b Protection functionality is limited. Only one circuit breaker
to detect high fault levels close to the substation and low fault
levels some distance away;
b Low fault levels can go undetected by circuit breaker and
FPIs, e.g. Sensitive Earth Fault (SEF).
Evolving sophistication Where a communications network is
expensive or difficult to implement, and in more critical parts of
networks, there is a move away from telecontrolled switches to
"infilling" with reclosers and using the telecontrolled switches as
sectionalisers. This introduces protection and automation
sophistication to the feeder.An example of a more "sophisticated"
feeder is where Load Break Switch / Sectionalisers are used instead
of telecontrolled switches. Communications is not essential to the
operation of feeders where reclosers and sectionalisers are used.
These networks can be automated to improve response times and do
not have to be remotely-controlled.
Figure 5: Fault Passage Indicator
Telecontrolled switches
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To analyse the use of Sectionaliser logic in a feeder, let us
consider the same open loop topology from the previous example but
replace the telecontrolled switches with sectionalising switches.A
sectionalising switch (sectionaliser) is a load break switch
capable of monitoring both current and voltage on all three phases.
The switch is combined with a controller capable of detecting
through-faults and upstream recloser operation. The current sensors
detect the number of fault currents which pass through the switch,
and the voltage sensors detect when the line is de-energised due to
upstream recloser operation. When the programmed number of
reclosing operations occurs, the controller opens the sectionaliser
during the dead time to isolate the downstream fault.These networks
are graded on the number of operations. That is upstream devices
are set to open at a higher number of Supply Interruptions (SI)
than the downstream devices. Therefore in this example the SI
counter for the sectionalisers is set to 3, 2 and 1
respectively.This example will demonstrate how the introduction of
basic automation can significantly reduce the operational
risks.
NO
SI=3 2 1
SI=3 2 1
Substation circuit breaker/recloserClosed sectionalising
switchOpen sectionalising switch
Figure 6: Typical Sectionaliser Network
Basic operation during fault conditionsb When a permanent fault
occurs, the following steps are taken:
b The substation circuit breaker or recloser trips and recloses
automatically while the sectionalisers count the supply
interruptions;
b The first sectionaliser to reach its set SI count opens during
the dead time of the recloser. This isolates the fault, and supply
to the upstream portion of the feeder is restored automatically on
the next reclose. The change of state in the sectionaliser is
reported via a communications network to the control room to fulfil
the FPI function;
b An operator:v opens the next downstream switch to isolate the
faulty segment;v reconfigures the protection in substation breakers
if necessary; andv closes the normally-open point to restore power
downstream of the faulty segment.At this point, power is restored
to the healthy parts of the network and it is possible for the
operator to despatch the line crews to the faulted segment of the
feeder to remove the fault. Once the entire feeder is healthy, the
operator can open the normally-open point and close the
sectionalisers to restore the network to the normal
configuration.
Figure 7: Automated Sectionaliser
Sectionalising switchgear
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Operational risksControl roomOnly the segments downstream of the
fault are affected by the reaction time of the control room. It is
therefore possible to prioritise the segments in the feeder and
plan the restoration times for each one. In practice the reaction
time for the remainder of the feeder is still influenced by the
same factors as in a telecontrolled feeder.The impact of operators
and the control room on the operational efficiency of this type of
network is less than before.
Fault passage indicationMonitored sectionalisers can be used for
fault passage indication. Fully featured sectionalisers offer
improved fault detection and controller capabilities. This may
reduce false indication issues when features such as inrush
restraint and cold load pickup are used. Additional FPIs can be
installed to improve network monitoring.Similar to the
telecontrolled switch network, communication failure can result in
incorrect switching operations and an increase in the time taken to
restore power.
CommunicationsDue to the sectionaliser logic, the feeder
upstream from the fault is unaffected by communication problems.
However, communications are required to sectionalise the downstream
portion of the network and to control the normally-open point. If a
complete breakdown of communications is experienced, it is possible
for the control room to use customer calls to determine the
affected parts of the feeder. In this way the maintenance crews can
focus their effort on the first sectionaliser within the
"complaints area", open it and then close the normally-open point.
Although not an ideal solution, in this case customers can be very
helpful.
Advantages b Relatively low initial cost of switchgear;
b Power is automatically restored to the upstream portion of the
feeder;
b The importance of communications is slightly reduced although
it is still required; Coordination between sectionalisers is
easier.
b Improved fault detection capabilities are possible; and
b FPI functionality is provided by the sectionalisers.
Disadvantages b Faults affect all the customers connected to a
feeder;
b Although improved, the level of automation is still low;
b Expensive communications infrastructure is still required;
b Operation is still dependent on the integrity of the
communications network;
b All faults cause substation circuit breaker operation - this
results in a shorter service life; and
b Protection functionality is limited. Only one circuit breaker
to detect high fault levels near the substation or low fault levels
some distance away.
Evolving sophistication The operational risks were substantially
reduced with the introduction of sectionalisers in the feeder.
However due to the limited protection features and the faults
affecting the entire feeder, this solution may not be suitable for
high priority customers - especially industrial customers.
Automatic circuit reclosers (reclosers) are designed to overcome
these problems.
Sectionalising Switchgear
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Today's reclosers are capable of sophisticated protection,
communication, automation and analytical functionality. With an
abundance of processing power at their disposal, utilities have the
flexibility to use the recloser as a standalone unit in a remote
location, or to integrate several units into sophisticated
substation automation systems. Whatever the application, the
reclosers are flexible enough to evolve with the utility's
requirements.Reclosers monitor current, voltage, frequency and the
power flow direction to protect the feeder. By coordinating the
reclosers correctly, only the recloser that is the closest to the
fault will trip. This is very important for the successful
implementation of reclosers. A recloser can be programmed to
automatically reclose when it tripped due to a fault. In this way,
power is restored automatically in the event of a transient fault.
If however the fault is permanent the recloser will trip again and
remain open. It is possible to have up to a maximum of 4 trips to
lockout
Coordination of reclosers To achieve current co-ordination on
reclosers in series, the operating time of each recloser must be
faster than any upstream device and slower than any downstream
device. That is, for the typical recloser network shown in Figure 8
where a specific fault current is flowing through the network,
"MP2" will trip quicker than "MP1" and "MP1" will trip quicker than
"F". This ensures that only the recloser immediately upstream of
the fault will trip. Pre-programmed Inverse Definite Minimum Time
(IDMT) protection curves or definite time to trip are used for
Phase and Earth Overcurrent protection. These protection curves
allow close grading with substation protection relays and other
protection devices. A safe margin (approximately 200 ms) between
operating times of successive devices must be maintained for all
fault levels on the network being protected.Feeders with different
electrical characteristics require different protection strategies.
Distribution Utilities worldwide have developed their own
strategies to suit their particular system conditions. For example,
fault analysis may show that the primary causes of transient faults
on a network are:b lightning induced power surges;
b wildlife getting caught in the power lines; and
b trees or branches falling on the lines.
Independent configuration of the time to trip for each
protection operation in the reclose sequence allows the utilities
to optimise the protection strategy for each network.The strategy
could typically be:A - The fault is first assumed to be lightning
related. A fast IDMT curve with a small time multiplier (eg 0.05x)
and an instantaneous element is used to ensure short exposure to
the initial fault current.B - This operation is followed by a very
short reclose time (eg 0.5 sec) to limit the effects on electronic
equipment such as PC's, VCR's, microwave ovens, etc.C - If the
fault is not cleared, on the subsequent auto-reclose a slow IDMT
curve with a long operating time allows tree or animal induced
faults on rural spur lines to be cleared by upstream fuses.D - The
reclose time that follows is long (eg 5 sec) to allow the animal or
branch to fall clear of the line if it is on the feeder or did not
cause fuse operation.E - If the fault is still present after the
auto-reclose it is assumed to be permanent and a fast IDMT curve
minimises exposure to fault currents.
Figure 8: Typical time diagram of a reclose sequence
Recloser systems
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Basic operation during fault conditionsIt is possible to operate
this type of network in either a "manual" mode where the operator
has to perform the reconfiguration of the network, or in a "Loop
Automation" mode where the reclosers perform all the task
automatically.
Manual modeIn the "manual mode" the following actions are
taken:b The recloser immediately upstream of the fault
automatically trips, recloses to lockout and remains open;
b An operator:v determines the location of the fault from the
recloser status and/or additional FPIs;v opens the next downstream
recloser to isolate the faulty segment;v reconfigures the
protection settings in anticipation of reverse power flow; andv
closes the normally-open point to restore power downstream of the
faulty segment.With power restored to the healthy parts of the
network it is possible for the operator to despatch the line crews
to the faulted segment of the feeder. Once the entire feeder is
healthy, the operator can open the normally-open point,
reconfigure, and close the reclosers to restore the network to the
normal configuration.
Figure 10: Solid Dielectric Recloser
.
NO
F MP1 MP2
F MP1 MP2TIE
Substation circuit breaker/recloserClosed automatic circuit
recloserOpen automatic circuit recloser
Figure 9: Typical Recloser Network
Recloser systems
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Loop AutomationIt is important to note that protection is the
first and foremost function of the reclosers, even in a loop
automation scheme. A more sophisticated recloser is required to
perform both protection and automation functions. In addition to
these, the reclosers have to measure power flow and voltage on both
sides of the recloser.To explain the basic operation of a Loop
Automation scheme, let's first define the reclosers as follows:b
Feeder recloser (F) - Recloser closest to the substation;
b Tie (TIE) - The open point recloser where the two feeders
meet. This is a normally-open point (NO); and
b Mid-point reclosers (MP) - All the reclosers positioned
between the Feeder and Tie reclosers.
Each of these reclosers is programmed with a different set of
rules when controlled by Loop Automation, which can be simplified
as follows:b The Feeder recloser trips when it loses supply.
b The Mid-point recloser changes to the reverse power flow
protection settings when it loses supply.
b The Tie recloser closes when it detects that supply to one
side of the network has been lost.
Loop Automation uses time, voltage, power flow and these simple
rules to isolate the fault and reconfigure the network without any
communications or operator assistance.In a loop automation network
the following actions will take place when a fault occurs:b The
recloser immediately upstream of the fault automatically trips,
recloses to lockout and remains open;
b Reclosers downstream of the fault automatically change the
protection settings in anticipation of power flowing in the
opposite direction; and
b The normally-open tie recloser closes automatically.
b Due to the fault still being present, the recloser immediately
downstream of the fault trips and locks out without reclosing.
This will automatically restore power to the healthy parts of
the network. An operator can now despatch line crews to the faulted
segment. It is also possible for the loop automation system to
restore the original configuration when the fault is cleared.
Recloser systems
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Operational risksControl room In a manual system the segment
downstream of the fault is affected by the reaction time of the
control room. To assist the operator during feeder reconfiguration,
recloser systems are capable of automatically applying forward or
reverse protection settings when power flow changes. In such a
system the operator is not required to change the settings in all
the reclosers.A loop automation system does not require any
operator intervention - all the operator has to do is despatch the
line crews.
Fault passage indicationThe ON/OFF status and even logs of
reclosers are commonly used to determine the location of faults on
feeders. With this inherent FPI functionality of the recloser,
false indication is eliminated. Separate FPIs can be used in
conjunction with the reclosers to assist the operators in
determining the exact location of faults on long feeders.
CommunicationsCommunications are not required at all in the loop
automation scheme. However, it may be desirable in order to monitor
the status of the network at several key points to assist
maintenance crews.In a manual recloser system, the feeder upstream
from the fault is unaffected by communication problems but
communications are required to reconfigure the downstream portion
of the network and to control the normally-open point.
Advantages b Customers upstream from the fault are not affected
at all.
b The Loop Automation scheme does not require communications;
and
b Power is restored quickly without any operator intervention,
when the loop automation scheme is used.
b Advanced protection features are available;
b Multiple groups of settings are pre-set to ensure an
effortless feeder reconfiguration when needed.
b Diagnostic tools are available with reclosers to assist in
feeder analysis.
b The manual system still requires communications although the
importance is reduced;
b With minimal effort the manual system can be upgraded to the
loop automation system.
Disadvantages b The manual system may still require
communications and it can affect the integrity of the feeder.
Evolving sophistication Reclosers provide a very robust system,
capable of protecting the feeder irrespective of many operational
factors. The number of customers affected by permanent faults is
minimised. However to further improve the feeder's immunity to
operational risks is very difficult and can be extremely
expensive.To further improve these sophisticated networks, the
focus shifts away from reducing operational risks to improving
reliability of supply through feeder automation.
Recloser systems
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A feeder automation network combines reclosers and
sectionalisers in a feeder to provide grading on both current/time
and number of operations. This is accomplished by introducing up to
two sectionalisers in each zone protected by a recloser.
SI=3 2 SI=3 2 F MP
F SI=3 SI=2 sect 1
sect 2
sect 3
Closed automatic circuit recloserClosed sectionaliser
Figure 11: Feeder Automation Network
Basic operation during fault conditionsIn a feeder automation
network the reclosers protect the downstream portion of the feeder
up to the next recloser. Similarly to the recloser network
described earlier, the recloser will trip and reclose in the
presence of a fault and the sectionalisers count the through-faults
similarly to the sectionalising switchgear network described
earlier. The difference is that if the fault occurs downstream of a
sectionaliser, the sectionaliser closest to the fault will open
before the recloser reaches lockout. Therefore, for this system to
work correctly, it is essential that the recloser is configured
with four trips to lockout and the sectionalisers are configured
with supply interrupt counters of three and two respectively.For a
feeder using one sectionaliser instead of two, the recloser is set
to three trips to lockout and the supply interrupt counter in the
sectionaliser is set to two. Please see the sectionaliser timing
diagram below for more information.
The sectionaliser timing diagram shows the importance of having
a recloser dead time greater than the sectionaliser operating time.
If this rule is ignored the sectionaliser contacts can open when
the power is ON. This will result in the switch interrupting fault
current, which can drastically shorten the operational life of the
switch, and the recloser will trip to lockout.
Figure 12: Gas Insulated Recloser
Operat ingt im e
Sect ionaliser cont act posit ion ON
OFF
Sect ionaliser source side vo lt age LIVE
DEAD
Sect ionaliser Current Fault Zero
Sect ionaliser Open com m and Tr ip Of f
Recloser Dead t im e
SI = SI+1
Figure 13: Sectionaliser Timing Diagram
Feeder automation
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15
The logic of a feeder automation network is best explained using
timing diagrams for different fault locations. Firstly, what
happens when a fault occurs in Section 1?The recloser "F" trips to
lockout, remains Open (OFF) and the sectionalisers do not change
state.
When a fault occurs in section 2 the recloser trips and recloses
twice before the sectionaliser "S1" opens to isolate the fault. The
third reclose operation restores power up to "S1". The recloser "F"
sequence resets after the sequence reset time.
A fault in section 3 will cause the recloser to trip and reclose
once before the sectionaliser "S2" opens to isolate the fault. Both
sectionalisers count the interruptions. The second reclose restores
power upstream of "S2". The sequence resets in the recloser "F" and
"S1" after the sequence reset time.
Advantages b Improved supply reliability when the segments are
broken into smaller sections, therefore reducing the length of
feeder that can be isolated in the event of a fault.
b Protection coordination is relative easy.
b Flexible solutions are possible.
b Existing recloser or sectionaliser networks can be upgraded to
incorporate full feeder automation with relative ease.
b The advantages of sectionalising switch and recloser networks
are combined in feeder automation networks.
b Creative protection solutions are possible at relatively low
cost.
b With full directional capabilities, the network will
automatically reconfigure itself when the normally-open point is
closed in the event of a fault.
Figure 14: Fault in Section 1
Figure 15: Fault in Section 2
Figure 16: Fault in Section 3
Feeder automation
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16
When feeder automation is used in a looped network, it is
necessary to consider using reclosers and sectionalisers with
advanced capabilities such as directional protection and loop
automation.With full directional capabilities, the reclosers and
sectionalisers are configured for protection with power flowing in
both the forward and reverse directions. Protection in both
directions is active at any given point in time. This allows the
utility to manually close the normally-open point in the event of a
fault, without having to reconfigure the other switchgear in the
feeder. It is therefore possible to focus on the communications
link to the normally-open point and by ensuring that it is
reliable, power restoration will always be possible.
In a network using Loop Automation, the switchgear controllers
will automatically reconfigure the protection settings during fault
conditions. Operation is very similar to that of a recloser-only
loop automation scheme. The major difference is that reclosing is
allowed to enable sectionalising, however the SI settings are
reduced.
In the segment shown above, recloser "F" protects the segment
during the normal configuration while recloser MP1 is protecting
the segment when power is restored. In a forward direction the
following settings are used:b "F" - forward protection and 4 trips
to lockout.
b "S1" - forward detection and SI = 3.
b "S2" - forward detection and SI = 2.
b "MP1" - forward protection and 4 trips to lockout.
In the reverse direction the settings will change to:b "F" is
the closest recloser to the substation. A fault upstream of "F"
will cause a loss of supply at the recloser and it will open to
isolate the substation. It therefore does not change protection
settings.
b "S1" - reverse detection and SI = 1.
b "S2" - reverse detection and SI = 2.
b "MP1" - reverse protection and three trips to lockout.
With only one sectionaliser per segment the settings are
slightly different.
In a forward direction the following settings are used:b "F" -
forward protection and 3 trips to lockout.
b "S1" - forward detection and SI = 2.
b "MP1" - forward protection and 3 trips to lockout.
In the reverse direction the settings will change to:b "F" is
the closest recloser to the substation. A fault upstream of "F"
will cause a loss of supply at the recloser and it will open to
isolate the substation. It therefore does not change protection
settings.
b "S1" - reverse detection and SI = 1.
b "MP1" - reverse protection and two trips to lockout.
A feeder automation network provides a flexible solution to any
protection challenge and is capable of evolving with the
distribution requirements.
Figure 17: Feeder Automation Loop
F S1 S2 MP1sect 1
sect 2
sect 3
Norm al pow er f low direct ion
Figure 18: Feeder Automation with 1 Sectionaliser
F S1 MP1sect 1
sect 2
Norm al pow er f low d irect ion
Feeder automation in a looped network
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17
In the diagram below of a basic network, reclosers are used as
substation breakers. Switchgear locations are indicated along the
main-line and the length of each section is shown. The location of
the sectionalisers used in analysing the feeder automation circuit
is also shown on the diagram. These sectionalisers are ignored in
the analysis of other network configurations.The load per feeder is
typically 4MW with 2MW, 1.5MW and 0.5MW of load in segment A, B and
C respectively. (A is the closest to the substation.)
Network DescriptionThe basic network shown below will be used to
analyse the cost implications of applying different levels of
sophistication in a network. The network contains two radial
feeders, tied together using a normally-open point. Each feeder
comprises three segments and each segment contains two spur lines.
The main-line of Feeder 1 is 37.5km long and the total length of
the spur lines is 62.5km. Feeder 2's main-line is 40km long and the
combined length of the spur lines is 60km. The overall length of
each feeder is 100km and the network supplies power to and area of
approximately 2000km².
Figure 19: Network Example Used in Cost Analysis
Cost analysis
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18
Costs ConsideredThe cost of the MV infrastructure is assumed
equal for all of the network configurations and is not included in
this analysis. Communication modems and other equipment associated
with the control room are also not part of the analysis.Table 4
provides a breakdown of the costs considered in the analysis. To
remove the effects of exchange rates, the cost of each item is
expressed as a multiple of the telecontrolled switch's cost. These
relationships may vary slightly from country to country.The
analysis firstly considers average revenue lost due to outages.
This average is based on the level of sophistication, topology and
segment lengths used in the network. The same average response and
fault repair times were assumed for each network type. Although
networks often evolve substantially during the useful service life
of 30 years, this analysis assumed the same load distribution
throughout the period.A telecontrolled switch network relies
heavily on the integrity of the communications infrastructure to
work reliability. Therefore the analysis includes an optical fibre
communications line installed along the entire length of the
main-line. Separate FPIs are also included for each switch.A
dial-up or radio control network is assumed for both the
sectionalising and manually controlled recloser networks. Although
communications are not required in the automated recloser and
feeder automation networks, some basic communications were included
to alert the control room of automation actions. Due to the
inherent FPI functionality of recloser and sectionalisers, separate
FPIs are not included in the analysis where these devices are
used.The analysis also refers to two types of reclosers and
sectionalisers - advanced and normal. Additional features such as
full directional protection capabilities, additional automation
features (such as loop automation), and powerful analytical tools
are available in the advanced products.
ResultsThe analysis considers the initial capital investment and
the impact of supply reliability to determine the optimum long-term
investment. Table 4 shows the impact of each component in the
analysis and helps to derive an order of preferred solutions to MV
power distribution:1. Feeder Automation network,2. Automated
Recloser network,3. Manual Recloser network,4. Sectionaliser
network,5. Telecontrolled Switch network.The lack of sophistication
in the telecontrolled switch network contributes to the high level
of revenue lost due to outages and the cost of the communications
network increases the cost of the initial investment substantially.
These "hidden" costs are sometimes overlooked and can drastically
reduce the return on investment. Although the feeder automation
network requires the largest initial capital investment of all, the
benefit of such a network is easily realised when the reduction in
revenue loss due to outages are considered.
ConclusionThis paper describes a range of protection and
segmentation options available in today's technology-driven market.
Although the options were explained using switchgear located on the
main-line of the network, it is possible to apply the techniques to
spur lines too. Existing networks can also keep up with future
requirements by evolving to more sophisticated technology. In some
cases it may be as easy as a firmware/software upgrade.Select your
supplier carefully and ensure that the hardware platform is
powerful and flexible enough to ensure sophistication where and
when it is needed.
Cost analysis
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19
Cost analysis
Glossary
DescriptionCost Multiple TeleControlled Sectionaliser Manual
Recloser Automated Recloser Feeder Automation
Cost due to outages (30years) Qty Value Qty Value Qty Value Qty
Value Qty Value
TeleControlled 9.08 p/a 30 272 - - - -
Sectionaliser 8.76 p/a - 30 263 - - -
Man. Recloser 8.45 p/a - - 30 254 - -
Auto. Recloser 7.65 p/a - - - 30 230 -
Feeder Auto 4.58 p/a - - - - 30 137
Protection equipment - - - - -
Substation recloser 5 2 10 2 10 2 10 2 10 2 10
TeleControlled Switch 1 5 5 - - - -
FPIs 0.5 5 2.5 - - - -
Sectionalisers 3 - 5 15 - - -
Advanced Sectionalisers 4 - - - - 6 24
Reclosers 5 - - 5 25 - -
Advanced Reclosers 6 - - - 5 30 5 30
Installed opticalfibre comms/km 0.3 77.5 23.25 - - -
Phone or RadioCommunications per point 0.2 - 5 1 5 1 5 1 5 1
Cost due to outages 272 263 254 230 137
Cost of protection equipment 41 26 36 41 65
Normalised cost 313 289 290 271 202
Cost differential [%] -8 -8 -14 -35
Table 4: Cost Analysis
Term Description
Cold Load Pickup When a feeder has been without power for an
extended period of time the load will lose its diversity. All the
thermostats will be turned on. That is air conditioners, fridges,
freezers, hot water systems etc. will all turn on when the feeder
is energised. This will cause an overload which can last for
several minutes. Cold load pickup overcomes this effect.
Dead time This is the duration where the recloser is OFF, after
a protection trip and before it recloses.
Inrush Restraint The short term overcurrent flowing through a
feeder the instant it is energised is known as inrush current.
Inrush restraint takes into consideration the short burst of these
currents.
Lockout Lockout is the state where the recloser remains open and
no further close operation is possible until the operator resets
the recloser.
Operating Time This is the time it takes for a sectionaliser to
OPEN after a trip command was issued.
Supply Interrupt (SI) Counter A sectionaliser increments the
supply interrupt counter when, after it detected a downstream
fault, the current and voltage drop to zero.
-
As standards, specifications and designs change from time
totime, please ask for confirmation of the information given in
thispublication.
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